The invention relates generally to tubing injectors for insertion of tubing into and retrieval from a well bore.
Coiled tubing well intervention has been known in the oil production industry for many years. A great length, often exceeding 15,000 feet, of small diameter, typically 1.5 inch, steel tubing is handled by coiling on a large reel, which explains the name of coiled tubing. The tubing reel cannot be used as a winch drum, since the stresses involved in using it, as a winch would destroy the tubing. The accepted solution in the oil industry is to pull tubing from the reel as it is required and pass it around a curved guide arch, or ‘gooseneck,’ so that it lies on a common vertical axis with the well bore. To control passage of tubing into and out of the well bore, a device called a coiled tubing injector head is temporarily mounted on the wellhead, beneath the guide arch. By use of the injector head, the tubing weight and payload is taken from the approximately straight tubing at the wellhead, leaving only a small tension necessary for tidy coiling to the tubing reel. Examples of coiled tubing injectors include those shown and described in U.S. Pat. Nos. 5,309,990, 6,059,029, and 6,173,769, all of which are incorporated herein by reference. Coiled tubing injector heads can also be used to run straight, jointed pipe in and out of well bores. General references to “tubing” herein should be interpreted to include both coiled tubing and jointed pipe, unless the context clearly indicates otherwise.
Coiled tubing is externally flush and is thus well adapted for insertion through a pressure retaining seal, or stuffing box, into a live well, meaning one with wellhead pressure that would eject fluids if not sealed. In a conventional coiled tubing application, an injector head needs to be able to lift, or pull, 40,000 pounds or more as tubing weight and payload when deep in the well. It also has to be able to push, or snub, 20,000 pounds or more to overcome stuffing box friction and wellhead pressure at the beginning and end of a trip into a well bore. Coiling tension is controlled by a tubing reel drive system and remains approximately constant no matter if the injector head is running tubing into or out of the well, or if it is pulling or snubbing. The coiling tension is insignificant by comparison to tubing weight and payload carried by the tubing in the well bore and is no danger to the integrity of the tubing. The tubing is typically run to a great depth in the well and then cycled repetitively over a shorter distance to place chemical treatments or to operate tools to rectify or enhance the well bore. It is by careful control of the injector head that the coiled tubing operator manipulates the tubing depth and speed to perform the programmed tasks.
In order that the injector head may manipulate tubing, it has to grip the tubing and then, concurrently, move the means of gripping so as to move the tubing within the well bore. Although other methods of achieving this aim are known, injector heads used for well intervention and drilling utilize a plurality of chain loops for gripping the tubing. There are many examples of such injector heads. Most rely on roller chains and matching sprocket forms as the means of transmitting drive from the driving shafts to the chain loop assemblies. Roller chain is inexpensive, very strong, and flexible. Yet, when the roller chain is assembled with grippers, which sometimes are comprised of a removable gripping element or block mounted to a carrier, the result is a massive subassembly, which is required to move at surface speeds of up to 300 feet per minute in some applications, changing direction rapidly around the drive and tensioner sprockets.
FIG. 1 schematically illustrates the basic components of an injector head that is a representative example of injector heads used for running tubing in and out of oil and gas wells. The injector head comprises, in this example, two closed or endless chains loops 12, though more than two can be employed. Each chain loop 12, which is closed or endless, is moved by drive shafts 14 via mounted sprockets 16 engaging with roller chain links, which form part of the total chain loop assembly. Each chain loop 12 has disposed on it a plurality of gripping blocks. As each chain loop is moved through a predetermined path, the portion of each chain loop that is adjacent to the other chain loop(s) over an essentially straight and parallel length, which is also the portion of its path along tubing 18, is forced by some means, for example the hydraulically motivated roller and link assembly 20, toward the tubing 18, so that the grippers along this portion of the path of the chain loop, which may be referred to as the gripping portion, length or zone, engage and are forced against the tubing 18, thereby generating a frictional force between the grippers and the coiled tubing that results in a firm grip. The non-gripping length(s) 22 of each loop 12, which extends between the drive sprockets 16 and idler sprocket 24, contrast to the chain along the gripping portion of the path of the chain loop, is largely unsupported and is only controlled, in the illustrated example, by centrally mounted tensioner 26. However, many modern injectors dispense with the central tensioners on the non-gripping length and control the chain loop tension instead by means of adjustment at the bottom idler sprocket 24.